​Western Australia pays battery operators in the WEM an annual capacity payment for being available during peak demand periods, a revenue stream separate from energy trading. The draft Benchmark Reserve Capacity Price (BRCP) for the 2028/29 capacity year lands at $491,700/MW/year, a 36% increase on last year. On its own, that looks like a strong signal for battery energy storage projects targeting the Western Australian market.

But the benchmark capacity price is only one piece of the pricing puzzle. Forecasted surplus capacity may reduce the Reserve Capacity Price (what actually gets paid) to $422,372/MW/year.

This article steps through what drove the 36% benchmark increase, how AEMO's surplus logic drops the price 14% below the benchmark, and what developers should weigh when deciding between fixed and floating pricing elections.

Executive Summary

• The draft benchmark price rises 36% to $491,700/MW/year. This is driven by a 6-hour capacity requirement, higher construction costs, and a $100,000/MW “Fixed Capital Charge”.
• AEMO forecasts a 495 MW peak surplus for 2028/29. This puts downward pressure on the price to a forecasted $422,372/MW/year. This limits the increase from 2027/28 to 17%.
• The ERA's $520/kWh benchmark cost sits well above CSIRO's national cost estimates of $301-377/kWh. The gaps suggests the BRCP more than compensates for typical build costs even after accounting for WA's regional cost premiums.
• A 200 MW battery locking in 10-year fixed pricing secures $844.7 million in capacity revenue. This is a substantial floor despite depressed multipliers. However, fixed pricing sacrifices Network Access Quantity priority and forfeits upside if surplus clears.

From $360k to $491k: what changed in the draft capacity price model

The Benchmark Reserve Capacity Price represents the estimated annualised cost of a “benchmark” 200MW / 1,200 MWh BESS, expressed in $/MW/year. For 2028/29, the Economic Regulation Authority (ERA) proposes a benchmark price of $491,700/MW/year.

Major contributors to the 36% increase include:

• Increased benchmark storage capacity from 4 to 6 hours (triggering capital cost uplift from 50% more battery modules plus higher power conversion and balance of plant costs),
• Labour cost inflation, and
• A new $100,000/MW Fixed Capital Charge for shared transmission network assets.

The ERA is accepting submissions on the draft price until Friday, 13 February 2026. The final benchmark determination is scheduled for 16 March 2026.

Complete assumptions behind the draft BRCP can be found in the ERA’s Draft BRCP Determination.

How ERA capacity costs compare to national estimates

The ERA's $628.8 million cost estimate for the 200 MW / 1,200 MWh benchmark battery works out to $520/kWh. This is well above CSIRO's GenCost estimates of $301-377/kWh for 4-8 hour batteries nationally in 2026. Part of that gap reflects genuine WA cost premiums. Tighter labour markets, higher construction wages, remote logistics, and the new Fixed Capital Charge all push WEM project costs above east coast benchmarks.

But the spread still suggests room for competitive economics. Developers achieving build costs closer to national averages would see the benchmark compensate for costs.

See the draft 2025-26 CSIRO GenCost report here.

How AEMO turns nameplate MW into credited capacity

AEMO runs the annual Reserve Capacity Mechanism (RCM) cycle, which allocates Capacity Credits and sets the prices paid per credit. Two mechanisms determine credited capacity:

Relevant Level Methodology (RLM) sets capacity based on observed performance during critical periods: evening peaks (Peak capacity), and shoulder or overnight periods (Flexible capacity).

Network Access Quantity (NAQ) applies a deliverability cap. If network constraints mean a battery can't physically deliver its capacity to load, NAQ limits the credited MW.

In practice, credited capacity is the lower of the two.

Why a 100 MW / 800 MWh battery would only get paid for 67 MW

A battery's credited capacity is based on 6-hour continuous discharge capability, shifted from a 4-hour requirement starting in the 2025 cycle. Shorter duration batteries entering from 2025 onward face derating proportional to duration. This means a 100 MW / 800 MWh battery would be credited at two-thirds of nameplate capacity, so 67 MW instead of 100 MW.

The derating penalty creates strong commercial incentive to invest in longer duration, as it unlocks a 50% increase in capacity revenue with cost increases much less than 50% greater.

Duration protections: Grandfathering rules protect batteries entering through the 2024 cycle or earlier from duration requirement changes for 10 years. The same 10-year protection covers 6-hour batteries entering from 2025 forward. This creates incentives to build to the current 6-hour standard but not materially longer as AEMO won't credit extra storage capacity until requirements change again.

What's different in 2026?

The 2026 cycle adds a 10-year Fixed Price contract option alongside the existing 5-year option for eligible new capacity. Batteries can lock pricing for a full decade, though fixed pricing elections accept lower Network Access priority and forfeit exposure to price increases in future cycles.

AEMO also adopted a probabilistic capacity calculation for intermittent generation, better reflecting wind and solar contribution under system stress scenarios. The shift increases capacity credits for renewables.

Unlike previous cycles, the ERA will finalise the benchmark price by 16 March 2026, after the EOI process for capacity. This means developers enter the EOI with the draft figure, but the ERA only confirms the final benchmark by the official capacity application window in April.

Why a higher BRCP doesn't guarantee higher revenues

The benchmark price climbed to $491,700/MW, but batteries will likely earn $422,372/MW. The 495 MW Peak surplus drives the multiplier to 0.86, limiting revenue growth to 17%.

How the multiplier works: The ERA finalises the benchmark. AEMO then compares forecast Reserve Capacity supply against the Reserve Capacity Target (for both Peak and Flexible capacity allocations). If supply exceeds the target (surplus), the multiplier falls below 1.0. The multiplier is applied to the benchmark price to calculate final Peak and Flexible prices, which are paid for capacity credited.

The 2028/29 surplus: AEMO's preliminary outlook shows the market heading toward 495 MW of Peak capacity surplus. Where the peak capacity target is 6,330 MW, and the estimated Peak Capacity Supply reaches 6,825 MW, this is an 8% oversupply. That surplus drives the multiplier down to approximately 0.86, placing the Peak RCP around $422,372/MW/year.

Why Flexible capacity will not deliver additional revenues

The 2028/29 outlook shows a 1,440 MW Flexible surplus against the preliminary target of 2,637 MW, a 55% oversupply. This pushes the Flexible multiplier well below the Peak multiplier. Batteries receive the Peak Capacity Price, then an additional payment equal to the greater of $0 or (Flexible RCP minus Peak RCP).

For developers, this means Flexible accreditation delivers zero additional revenue above Peak payments, so qualifying for Flexible is commercially pointless until surplus conditions reverse.

Key dates for entering the 2028/29 capacity market

The 2026 cycle follows a structured timeline from January 2026 through to final capacity credit assignment in November 2026:

• Expression of Interest window (15 January to 3 March 2026)
• Capacity application window (14 April to 24 June 2026)
• Capacity assignment window (12 August to 30 September 2026)
• Final capacity allocation and pricing window (1 October to 6 November 2026)

With the first trading day commencing 1 October 2028.

The full cycle timetable with detailed regulatory milestones is published on AEMO's website.

Considerations for developers

• The draft benchmark capacity price jumped 36% to $491,700/MW, but surplus dynamics limit the cycle's growth to 17%.
• A 200 MW battery securing fixed pricing at $422,372/MW/year locks in $844.7 million over 10 years before factoring in other revenue sources.
• The benchmark cost sits well above CSIRO's $301-377/kWh national estimates, suggesting the capacity price will more than compensate for battery costs, particularly for developers achieving costs closer to the national average.
• The benchmark price gains are structural. As long as 6-hour duration remains standard and construction costs stay elevated, the baseline should hold relative to battery costs.
• Surplus will suppress what you actually earn. Revenue upside depends on future cycles tightening the surplus through coal retirements and storage demand growth.
• Fixed pricing offers certainty for financing, but sacrifices upside and NAQ priority.

Bottom line: Ten years of capacity revenue at $422k/MW delivers substantial cash flow against benchmark costs that appear conservative relative to achievable build costs. Fixed pricing makes sense for projects prioritising financing certainty. Floating pricing suits developers betting on surplus clearance and willing to accept near-term multiplier compression for medium-term upside.